The present invention relates to solvents useful for gas separation of contaminants and/or undesired compounds and elements from gas streams. Carbon dioxide and hydrogen sulfide are two examples of acid gases for which it would be advantageous to separate from gas streams. As contaminant species, acid gases occur in natural gas streams, bio-gas streams, and in other process gas streams in chemical processing and refining operations. Flue gas streams in power production, especially in coal-fired power-plants, also contain a significant amount of carbon dioxide, which has been attributed to be a major cause of global warming and environmental issues. Removal of carbon dioxide from these gas streams is a continuous effort for more efficient and cost-effective processes.
A number of methods are available for removal of acid gases from product gas streams. Some of the more commonly used methods are chemical solvents, physical solvents, membranes, and cryogenic fractionation. Some methods for carbon dioxide capture include the absorption of CO2 in a solvent, either chemical or physical, and subsequent solvent regeneration at elevated temperature and/or reduced pressure. The regeneration of chemical solvents is achieved by the application of heat whereas physical solvents can often be stripped of impurities by reducing the pressure without the application of heat. Physical solvents tend to be favored over chemical solvents when the concentration and partial pressures of acid gases or other impurities are very high. Unlike chemical solvents, physical solvents are non-corrosive, enabling use of lower-cost materials for construction. In general, the economics of CO2 recovery is strongly influenced by the partial pressure of CO2 in the feed gas. At low partial pressures, physical solvents are impractical because the compression of the gas for physical absorption is expensive, and chemical solvents are predominantly used. However, if the gas is available at high pressure, physical solvents are a better choice than chemical solvents.
The concentration of heavy hydrocarbons in the feed gas, like in raw natural gas, also affects the choice of the gas treating solvents. If the concentration of heavy hydrocarbons is high, a physical solvent may not be the best option, due to higher co-absorption of hydrocarbons, particularly pentanes plus. Unlike natural gases where hydrocarbon co-absorption can be a problem for physical solvents, synthesis gases do not contain appreciable quantities of hydrocarbons. This makes physical solvents particularly applicable to synthesis gas treatment, or for cleanup of biogas from landfills or anaerobic digesters in waste-water treatment plants.
The membrane process is applicable for high pressure gas containing high acid gas concentrations. CO2 recovery is accomplished by pressure-driven mass transfer through a permeable membrane where separation is due to the differences in permeation rate of different compounds. The acid gas is recovered at low pressure. A high purity product containing approximately 95% CO2 can be achieved with one or two stages, depending upon feed gas pressure and percent recovery. Economic considerations may dictate additional capital and incremental energy requirements to increase feed pressure and/or utilize two-stage separation with recompression of gas from the first stage.
Chemical Absorption of CO2:
CO2 can be absorbed by many basic sorbents including alkali carbonate, aqueous ammonia, and alkanolamines. Ethanolamines (MEA, DEA, MDEA, DGA, etc.) and hot potassium carbonate are chemical solvent processes which rely on chemical reactions to remove acid gas constituents from sour gas streams. Chemical absorption with amines is one CO2 capture technology actively explored. Amines are useful for CO2 capture because they can increase the solubility of the CO2. The main issue is how the sorbents can be regenerated. The binding between sorbent molecules and CO2 generally is strong and this offers a fast and effective removal of most of CO2 in one stage of absorption. Ideally, a mole of amine can absorb one mole of carbon dioxide or one mole of hydrogen sulfide. However, the strong binding between CO2 and the sorbent molecules is also one of the causes for high energy requirement for solvent regeneration. A second concern is the control of impurities and minor components in the gas stream, including H2S, SO2, oxygen, etc. that may degrade the sorbents. These components have to be removed before the gas enters the absorber, or treated with appropriate measures. Because many sorbents are corrosive, diluted solutions (around 18% for MEA) are typically used.
Chemical solvents, like amines, are usually used as aqueous solutions, either by themselves or as mixtures, and with or without catalysts (like piperazine, PZ). Monoethanolamine (MEA, a primary amine) is used as a 15-20% solution in water, diethanolamine (DEA, a secondary amine) as a 20-30% solution in water, and N-methyl diethanolamine (MDEA, a tertiary amine) as a 30-50% solution in water. If a cost-effective non-thermal pathway can be used to desorb CO2 and regenerate the amines, the extraction of CO2 from low-pressure raw gas streams would be more economically viable.
A major limitation of using MEA as a sorbent is its high heat of absorption for CO2 (72 KJ/mole), equivalent to 18% of the combustion heat of carbon (393.5 KJ/mole)). Secondly, the concentration of MEA used is at 15-20%; this means energy has to be applied to also heat the water solution in the stripper, and possibly evaporate some water in the process. Water is needed for the absorption reaction of CO2, because water enables the formation of bicarbonates, which then preferentially react with the amines exothermically. However, during desorption of the CO2 and thermal regeneration of the amines, the high specific heat of the water carries a considerable energy penalty, and the use of expensive heat exchanger systems to optimize heat balances is needed. The total regeneration energy required is about 900 kcal/kg CO2, or 165 KJ/mole CO2, equivalent to 42% heat from burning a mole of carbon, and 25% of the total combustion energy generated by burning coal. Although the stripper uses low-grade steam, it still causes almost a 20% reduction in power generation for a coal-fired power plant, if all the CO2 in the flue gas has to be removed and sequestered.
Another problem with the use of amines for CO2 capture involves the buildup of impurities and contaminants in the solution which must be removed. For example, small non-charged degradation products, such as low molecular weight amines, are more volatile than the starting amine and can result in emission issues and/or the need for subsequent costly water washing. This is especially the case when some volatile degradation products cannot be removed by ion exchange or other traditional techniques, and are undesirably contained in the exiting gas stream discharged into the atmosphere. Thus, removal or elimination of such unwanted amines, before the gas is discharged from a plant, is desired.
The use of certain solvents, such as an amine attached to a water soluble polymer backbone, can improve the purity of the stream subsequently released into the environment, as well as alleviate the need for some additional processing (e.g., subsequent complex scrubbing techniques and/or water washing), thereby also improving the efficiency of the process. Known amines can be polymerized to obtain a water soluble polymer containing an amino group for use as a solvent. An example of a commercially available water soluble polymerized amine includes polyethyleneimine (PEI). For instance, PEI-150 is a 33% aqueous solution of 10,000 molecular weight polyethyleneimine from Virginia Chemicals. The high molecular weight of PEI unfortunately results in a very high viscosity, leading to higher pumping costs and less efficient gas-liquid mixing.
Suitable amines for attachment to/reaction with a water soluble polymer include primary and secondary amines. A primary amine has one of three hydrogen atoms in ammonia replaced by an organic substituent bound to the nitrogen atom. A secondary amine has two organic substituents bound to the nitrogen atom together with one hydrogen atom. It has been further determined that use of tertiary amines are less suitable than use of primary and secondary amine because, for example, the primary and secondary amines will become tertiary amines upon reaction with the water soluble polymer. Thus, suitable amines for reaction with/attachment to the afore-referenced water soluble polymer having functional groups generally denoted as, e.g., NH3, NH2R1 and NHR1R2; where R1 and R2 is selected from, but not limited to —CH2CH2OH, —CH2CO2H, —CH2CH(OH)CH3, —CH3, CH2CH3 and combinations thereof. Further examples of suitable amines include primary alkyl and secondary alkyl amines in general, methylamine, dimethylamine, ethylamine, diethylamine, monoethanolamine (MEA); diethanolamine (DEA); dimethylamine and secondary cyclic amines such as piperazine and piperidine. Combinations of any of the foregoing could also be employed.
The water soluble polymers to which the afore-referenced amines are attached to include any water soluble polymer having functional groups thereon which are capable of reacting with the amine. For example, the water soluble polymer comprises a functional group such as —CH2Cl, —CH2Br, OH, HCH(O)CH2 (an oxirane group) among other suitable functional groups. A particular example of a suitable water soluble polymer having the desired functional group(s) for attachment to the amine is a chlorinated polymer known as Fibrabon 35® from Diamond Shamrock Chemical Company. Another suitable example includes polyvinyl alcohol (PVA), among others.
Diglycol amine (DGA) can be used at 40% concentration, and thus has twice as much CO2 loading capacity as MEA (currently used at 18%). Several sterically hindered amines have been examined and it is found that some hindered amines can reduce the heat of regeneration by 20%. Sterically hindered amines use geometrical effect to weaken the binding between the CO2 and amine molecules.
Physical Absorption of CO2:
In physical absorption, the CO2 gas molecules get dissolved in a liquid solvent, and no chemical reaction takes place. The binding between the CO2 molecules and solvent molecules, being either Van der Waals type or electrostatic, is weaker than that of chemical bonds in chemi-absorption. The amount of gas absorbed is linearly proportional to its partial pressure (Dalton's and Henry's laws). Physical solvents such as DEPG, Dimethyl Ether of Polyethylene Glycol (Selexol or Gensorb 1753, NMP, N-Methyl-2-Pyrrolidone (Purisol), Methanol (Rectisol), and Propylene Carbonate (Fluor Solvent) are becoming increasingly popular as gas treating solvents, especially for coal gasification applications. The desorption can be achieved either by lowering pressure as in pressure swing absorption (PSA), or raising the temperature as in temperature swing absorption (TSA). Physical absorption has been used in synthesis gas production processes to separate CO2 from hydrogen and CO. These processes include: Rectisol that uses methanol as solvent, Selexol that uses dimethyl ether of polyethylene glycol (DEPG), Sepasolv that uses n-oligoethylene glycol methyl isopropyl ethers, MPE), Purisol that uses N-methyl-2-pyrrolidone, NMP), and Gaselan that uses N-methylcaprolactam (NMC).
Physical solvents tend to be favored over chemical solvents when the pressure and concentration of acid gases or other impurities is very high in the raw gas inlet, and other hydrocarbons are not present, which could also preferentially dissolve in the solvent. In addition, physical solvents can usually be stripped of impurities by reducing the pressure without the addition of heat. Physical solvents such as methanol, NMP (normal methyl pyrolidinone) [U.S. Pat. No. 3,103,411 and U.S. Pat. No. 4,208,382], Selexol, propylene carbonate [U.S. Pat. No. 2,926,751] and others are widely used for the removal of CO2 and H2S from gases such as natural gas and syngas from coal gasification.
However, physical solvents that can approach the CO2 absorption capacity of chemical solvents need to be developed. In a state-of-the-art carbon dioxide absorption process described in literature, using MEA as the solvent, the concentration of MEA in solution was 0.3 g/g. This gives a typical concentration of carbon dioxide in the MEA solution, as calculated, at 43.8 g/l, using a solution density of 1.013 kg/l, and showing a typical carbon dioxide uptake of 0.2 mol/mol. It also has to be taken into account that the typical uptake for MEA solutions is still relatively inefficient and below the maximum uptake concentration, which can theoretically be five times as high, corresponding to 1 mol carbon dioxide per mol MEA, as would be obtained in a stoichiometric reaction. This would result in a maximum concentration of 219 g/l, which is more than 10 times the maximum concentration reached in physical solvents. In reality, such high uptake values in MEA are not achieved, especially since the presence of water is needed for CO2 absorption by the amines, and thus, the amines have to be an aqueous solution. In addition, the regeneration energy would be very high, as the carbamates formed would need to be broken down to regenerate the solvent by releasing the absorbed CO2.
A mixture of low volatility CO2-philic oligomers known as poly(ethylene glycol) di-methyl ether, DEPG, is the current solvent of choice in the CO2 capture process. Known as Selexol, it is a commercial mixture of poly(ethylene glycol) dimethyl ethers with optimised properties. Poly(dimethylsiloxane), PDMS, and poly(propylene glycol) di-methyl ether, PPGDME, are potentially better solvents, compared to DEPG, in this process due to their limited miscibility or immiscibility with water, a constituent in the natural gas, bio-gas gas or flue streams, but their high viscosity is an issue, an important property for gas transport in and out of the liquid phase in the physical solvents. Other solvents currently used for physical absorption of carbon dioxide are, for example, methanol and sulfolane. Ionic liquids have been suggested as alternative physical solvents for carbon dioxide absorption due to their extremely low vapor pressures. Various ionic liquids were found to absorb CO2 with high selectivity over N2. Polymers of ionic liquids have also been reported to have high CO2 absorption capacity and selectivity over N2, with fast and completely reversible absorption. However, ionic liquids are at present considered to be too expensive for large-scale industrial applications.
There is an urgent need for processes using chemical solvents, without the high energy penalty for solvent regeneration, as well as physical solvents that can match the high CO2 absorption capacity of chemical solvents, with easy regeneration. Alternatively, a new class of solvents that have the high absorption capacity of the alkanolamines, but the low energy regeneration capability of physical solvents is desirable, as described herein.